Wellbore pumps in series, including device to separate gas from produced reservoir fluids

ABSTRACT

A pump system for a wellbore includes a production tubing nested within a wellbore. At least two pumps are disposed in the production tubing and are axially spaced apart from each other. One of the pumps is removable from the production tubing while the production tubing remains in place. A fluid intake conduit is disposed outside the production. The fluid intake conduit is in fluid communication with an interior of the production tubing below a lower one of the pumps and at a position of an intake of an upper one of the pumps. At least one fluid discharge conduit is disposed outside the tubing and inside the wellbore. The at least one fluid discharge conduit is in fluid communication with the interior of the production tubing proximate a discharge of the lower one of the pumps and above the upper one of the pumps.

CROSS REFERENCE TO RELATED APPLICATIONS

Continuation of International Application No. PCT/IB2017/057503 filed onNov. 29, 2017. Priority is claimed from U.S. Provisional Application No.62/440,060 filed on Dec. 29, 2016. Both the foregoing applications areincorporated herein by reference in their entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable

NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT

Not Applicable.

BACKGROUND

This disclosure relates to the field of producing fluids fromunderground wellbores, where the fluids need artificial assistance to betransported to the surface.

Wellbores used for the production of fluids disposed in undergroundformations (for example from a hydrocarbon reservoir) to the surfaceoften must be equipped with artificial lift devices such as downholepumps to assist pushing fluids to the outlet of the wellbore proximatethe surface. A common pump type is electrically driven, and is known asan electrical submersible pump (ESP). To obtain various fluid lift ratesto the surface, the length and dimension of the pump determines thefluid flow rate to surface that may be obtained. ESP fluid lift flowrates typically are related to the outer diameter and length of the ESP.Smaller diameter and smaller length corresponds to lower possible flowrates; larger outer diameter and longer pumps may have higher possibleflow rates.

Often wellbores include a conduit called a “casing” that has a less thanoptimum internal diameter for an artificial lift system to be installed,which frequently means that a pump (e.g., an ESP) of smaller outerdimension than may be desirable must be used, and correspondinglyresults in insufficient fluid lift rates to the surface. Also, wellboresare often deviated (inclined from vertical), which results in a lengthrestriction for the pump(s); pumps generally cannot be exposed to largebending as would be required to install such pumps in a wellbore thathas high change in deviation per unit length (“dog leg severity”). As anexample, the productive reservoirs in the Barents Sea located north ofNorway are at very shallow depths below the seafloor. Highly inclinedand/or horizontal wells are often required to make producinghydrocarbons from such reservoirs economically feasible. The dog legseverity of such wells may create challenges in deploying pumps deepenough in such wells to deliver optimum flow and reservoir drainage. Itshould also be noted that such reservoirs will often produce fluids veryclose to their bubble point, further creating a need for having pumps asdeep into the wellbores as possible.

Another aspect of shallow reservoirs such as may be found in the BarentsSea is that it is remote from shore, and replacing pumps that arepermanently mounted onto the production tubing will require lengthy andcostly mobilization of a marine drilling unit. Such conditions result inlost production while waiting for the marine drilling unit to bemobilized to the well location and made ready for the well intervention.

If pumps in subsea wells can be replaced by light intervention, as forexample by wireline or similar, a less costly vessel can be used. Suchvessels will most likely also have much less mobilization time thanmarine drilling units, which may substantially reduce lost production incase of pump failures.

Hence, there is a need for a solution to the difficulties of installingpumps in highly inclined wellbores, and in particular such wellboreslocated offshore.

ESPs may suffer from lack of reliability, and therefore it is anadvantage to install several pumps as redundancy in a wellbore, so thatproduction is not completely stopped in case of failure of one pump. Analternative, as described in U.S. Pat. No. 9,166,352 issued to Hansen,is to equip a pump with an electrical wet connect system, so that a pumpcan be retrieved and installed without having to retrieve the entirewell completion system.

There are technologies known in the art where power to operateindividual wellbore pumps can be engaged and disengaged downhole in thewellbore, as for example an hydraulically activated switch provided byRMS Pumptools, North Meadows Oldmeldrum Aberdeenshire AB51 0GQ, UnitedKingdom and described in U.S. Pat. No. 8,353,352 issued to Leitch. It isalso possible to implement a downhole electronic addressing system,which could be used to engage and disengage electrical power toindividual or several wellbore pumps. Operation of a downhole addressingsystem may be performed using an ESP power cable, or by using a separatecable that may also be used for downhole sensors and the like. Such aswitching system may be incorporated into an ESP coupler as described inU.S. Pat. No. 9,166,352 issued to Hansen. Also a downhole switch isdescribed in U.S. Patent Application Publication No. 2015/003717,entitled, “Electric submersible pump having a plurality of motors.”

SUMMARY

In one aspect, the disclosure relates to a pump system for a wellbore. Apump system according to this aspect of the disclosure includes aproduction tubing nested within a casing in a wellbore or disposedwithin an open wellbore. At least two pumps are disposed in theproduction tubing and axially spaced apart from each other. At least oneof the at least two pumps is removable from the production tubing whilethe production tubing remains in place in the wellbore. At least onefluid intake conduit is disposed outside the production tubing andinside the wellbore. The at least one fluid intake conduit is in fluidcommunication with an interior of the production tubing below a lowerone of the at least two pumps and at a position of an intake of an upperone of the at least two pumps. At least one fluid discharge conduit isdisposed outside the tubing and inside the wellbore. The at least onefluid discharge conduit in fluid communication with the interior of theproduction tubing proximate a discharge of the lower one of the at leasttwo pumps and above the upper one of the at least two pumps.

A method for pumping fluid from a wellbore according to another aspectof the disclosure includes operating at least one of at least two pumpsdisposed in a production tubing disposed in the wellbore. At least oneof the at least two pumps is removable from the production tubing whilethe production tubing remains in place in the wellbore, at least onefluid intake conduit disposed outside the production tubing and insidethe wellbore, the at least one fluid intake conduit in communicationwith an interior of the production tubing below a lower one of the atleast two pumps and at a position of an intake of an upper one of the atleast two pumps, at least one fluid discharge conduit disposed outsidethe tubing and inside the wellbore, the at least one fluid dischargeconduit in fluid communication with the interior of the productiontubing proximate a discharge of the lower one of the at least two pumpsand either proximate an intake of or above the upper one of the at leasttwo pumps.

Other aspects and possible advantages of the present disclosure will beapparent from the description and claims that follow.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a wellbore consisting of a casing with a productiontubing inside, where the production tubing incorporates several pumps.

FIGS. 2A, 2B and 2C illustrate a method of installing two ESPs intandem, where fluid production from a reservoir enters the ESPs intakesfrom the casing side.

FIG. 3 illustrates a production tubing with several retrievable pumpsplaced within the tubing at various depths.

FIG. 4 illustrates a production tubing with several non-retrievablepumps placed within the tubing at various depths.

FIG. 5 illustrates that a combination of a permanently and one or moreretrievable pumps are also possible, combining what is illustrated inFIG. 3 and FIG. 4.

FIG. 6 illustrates a cross section of the wellbore with the pump(including possible electrical coupler/connection), the electrical cableand several fluid transport conduits.

FIGS. 7A and 7B illustrate the difference between using a pump with asmaller outer diameter and/or shorter length to be able to be deployedfurther into high dog leg severity wellbores.

FIG. 8 illustrates a cross sectional example of a casing string where anESP, an electrical wet connect, ESP cable and bypass tubing strings areshown.

FIG. 9 illustrates how an ESP assembly may be configured, including theelectric wet connect system.

FIG. 10 illustrates how a gas separating device may be incorporatedbelow the fluid distribution to the above mounted pumps.

FIG. 11 illustrates a booster system receiving gas from one or severalgas feeding conduit(s), and then discharging the gas into the producedfluids from one or several wellbore pumps.

FIG. 12 illustrates a gas separation system located below the pumpsystem, where the separation system is sealing externally against theproduction casing.

DETAILED DESCRIPTION

The present disclosure describes structures wherein a plurality ofwellbore fluid pumps can be installed in a wellbore as individual units,where each pump below an uppermost pump transfers fluids to a locationabove the uppermost pump, or to an area below the uppermost pump, if theuppermost pump is capable of pumping the combined volume delivered fromthe pumps below. Bypass (flow) conduits may be provided for transportingreservoir fluids from below the lowermost pump to one or more pumpsmounted above the lowermost pump, as well as transporting fluids fromthe various pumps to a location below and/or above the uppermost pump.One or several fluid transport tubes may be disposed between eachrequired pump location may be provided in some embodiments to obtainincreased fluid transport rate to surface. The axial distance along thewellbore between the various pumps may be different. By utilizing threepumps, for example, where two pumps in operation provide sufficientfluid flow rate to surface, provides redundancy and more reliableproduction. If one of the two operating pumps fails, the third pump canbe activated to resume the total required fluid lift rate to surface.

Using one or more wet connect coupler(s), as for example the couplerdescribed in patent U.S. Pat. No. 9,166,352 issued to Hansen, the pumpscan be replaced by light wellbore intervention instead of having tomobilize and use a much more costly drilling rig.

In some embodiments, a production packer (annular seal between awellbore casing and a nested production tubing) may be mounted on theproduction tubing below the pumps, but can also be mounted on theproduction tubing above the pumps if required. The latter method is morecomplex, because the packer will need to have bypass devices to enablepass through of the electrical cable. However, pump packers with annularbypass is a commonly available technology today.

In some embodiments, a well completion may consist of a larger outerdiameter, permanently installed ESP capable of lifting total requiredfluid flow rate amount of fluid per combined with one or severalretrievable ESPs (e.g., wireline or coiled tubing retrievable ESPs. Theretrievable ESPs may function as a back-up to the permanently mountedpump, and may also be sized to together be able to provide the totalrequired fluid flow rate

In some embodiments, a gas separator may be installed below the ESPs,where gas may be discharged to an area above the ESPs. The gasseparation system may be retrievable by wireline, coiled tubing or thelike, or may also be permanently mounted as part of the productiontubing.

While the various embodiments disclosed herein are described in terms ofa wellbore having a casing disposed therein, it will be appreciated bythose skilled in the art that the various aspects of pump systemsaccording to the present disclosure may be used in wellbores not havingcasing (“open wellbores”), and the scope of the disclosure should beconstrued accordingly.

FIG. 1 illustrates an example wellbore having a casing 14 disposed inthe wellbore (not shown separately) to hydraulically isolate formationsdisposed outside the casing 14 and to maintain mechanical integrity ofthe wellbore. The casing 14 may comprise a nested production tubing 12inside, where the production tubing 12 includes a plurality of pumps,for example, electrical submersible pumps (ESPs). In the present exampleembodiment the tubing 12 comprises three axially spaced apart pumps,shown at 10A, 10B and 10C, respectively. An annular seal 16, oftenreferred to as a packer, production packer or a tie-back seal stem, maybe located proximate the lower end of the production tubing 12 in theannular space between the production tubing 12 and the casing 14. Thepumps 10A, 10B, 10C may be disposed in the production tubing 12 abovethe annular seal 16. Each pump 10A, 10B, 10C has a dedicated fluid pathfrom the wellbore below the annular seal 16 to the respective intake ofeach pump 10A, 10B, 10C. In the present embodiment, the lowermost pump10C may have its intake path through the part of the production tubing12 disposed below the lowermost pump 10C. The middle 10B and upper 10Apumps may have corresponding intake flow lines 22B, 22A that are fluidlyconnected, at 22B1 and 22A1, respectively to the interior of theproduction tubing 12 below the lowermost pump 10C. The lowermost pump10C and middle pump 10B may each have as well a respective fluiddischarge conduit 24C, 24B above each pump 10C, 10B Such fluid dischargeconduits 24C, 24B may be fluidly connected to the interior of theproduction tubing 12 above the uppermost pump 10A at connections 24C1,24B1, respectively. Each fluid intake flow line 22A, 22B as well as eachfluid discharge conduit 24B, 24C may consist of a plurality ofindividual conduits disposed in the annular space between the casing 14an the production tubing 12 lines to obtain high fluid flow capabilitywith as small outer total diameter of the pumps 10A, 10B, 10C and lines22A, 22B, 24A, 24B as practical when the components are assembled andinserted into the casing 14. If the pumps 10A, 10B, 10C are suitablysized for flow rate, if one of the pumps fails, such failure does notaffect the operation of the other pumps, and full fluid flow rate fromthe wellbore to surface may be maintained. It is important to understandthat the drawings are not to scale. Also, pumps of a smaller dimensioncan be used, where the required total fluid flow rate is obtained bymost or all pumps being operational. Also, it should be understood thateach pump 10A, 10B, 10C may have one or several fluid flow conduits toand/or from each respective intake and discharge locations describedabove. Intake and discharge locations for the respective fluid flowconduits will depend on the configuration of and the number of pumpsused in any particular embodiment.

In the example embodiment shown in FIG. 1, the production tubing 12 maycomprise a wet mateable electrical and mechanical coupler 18A, 18B, 18Cfor seating each respective pump 10A, 10B, 10C and making electricalconnection to each respective pump 10A, 10B, 10C. Furthermore, the lines22A, 22B, 24A, 24B may be affixed to the production tubing 12 prior toor during insertion of the production tubing 12 into the casing 14. Thewet mateable electrical and mechanical couplers 18A, 18B, 18C may besubstantially as described in U.S. Pat. No. 9,166,352 issued to Hansen.In such case, the pumps 10A, 10B, 10C may be inserted into and seated intheir respective positions within the production tubing 12 by means ofconveyance such as wireline (armored electrical cable), coiled tubing orjointed tubing. The pumps 10A, 10B 10C may be likewise removed from theproduction tubing if and as necessary. It will be appreciated by thoseskilled in the art that using wireline conveyance for the pumps 10A,10B, 10C may provide operational advantages such as lower transportationcost and lower operating cost.

FIGS. 2A, 2B and 2C illustrate a known configuration for installingmultiple ESPs 10A, 10B in tandem. The pumps 10A, 10 are disposed outsidethe production tubing 12 and have their respective intakes in fluidcommunication with the interior of the casing (14 in FIG. 1). Dischargefrom each pump 10A, 10B is connected to the interior of the productiontubing using a Y-connector 28 coupled within the production tubing 12along one leg of the Y-connector 28 and having a coupling to thedischarge of each pump 10A, 10B through the other leg of the Y connector28. The drawback of the configuration shown in FIGS. 2A, 2B and 2C isthat the casing (14 in FIG. 1) is subjected to flow erosion because ofhigh fluid flow velocity in the annular space, as well as having aY-tool 28 on top of each pump 10A, 10B. Another possible drawback isthat the tubing connected leg of each Y-connector 28 needs to be largeenough to allow installation and retrieval of a blanking plug 27, whichreduces the amount of room available for the pumps 10A, 10B. Anothertypical method is to mount an outer shroud on a ESP assembly, as analternative to the bypass tube approach described in this patentapplication. Using bypass tubes will allow more room for the ESP, andtherefore has an advantage to using a shroud. Also, using a shroudprevents the ability to utilize retrievable ESP's.

FIG. 3 illustrates a production tubing with several retrievable pumps10A. 10B, 10C placed within the production tubing 12 at various axialpositions along the interior of the production tubing 12. Theretrievable pumps 10A, 10B, 10C can be pulled to surface from within theproduction tubing 12, as well as installed through same, without havingto pull the production tubing 12 to the surface. A respective electricalwet mateable coupler 18A, 18B, 18C for each pump 10A, 10B, 10C ispreinstalled in the production tubing 12, being for example the type asdescribed in U.S. Pat. No. 9,166,352 issued Hansen. Fluid intake anddischarge tubes may be similar to those as explained with reference toFIG. 1. Being retrievable pumps, a sealing system on each pump isrequired to eliminate any unwanted cross flow and leakages.

FIG. 4 illustrates a production tubing 12 with several non-retrievablepumps 110A, 110B, 110C placed within the production tubing 12 at variousaxial positions. In case of failure of one or more of the pumps 110A,110B, 110C, the production tubing 12 will need to be pulled to thesurface for replacement of any of the pumps. The fluid intake anddischarge tubes may be substantially as explained with reference to FIG.1.

FIG. 5 illustrates that a combination of a permanently 110C and one ormore retrievable 10A, 10B pumps are also possible, combining what isillustrated in FIG. 3 and FIG. 4. Here, the permanently mounted pump110C can be capable of lifting the total required fluid flow rate to thesurface, where back-up is provided by one or several retrievable pumps10A, 10B that would also be able to in combination lift the totalrequired fluid flow rate to the surface. In case of failure or lack ofperformance of the permanent pump 110C, the back-up pumps 10A, 10B canbe engaged. If one or several of the back-up pumps 10A, 10B fail also,it is possible to replace them without having to remove the productiontubing 12. Flow lines for intake and discharge of the pumps 10A. 10B,110C may be substantially as explained with reference to FIG. 1.Similarly, each of the retrievable pumps 10A, 10B may be seated in arespective wet mateable connector 18A, 18B also as explained withreference to FIG. 1.

FIG. 6 illustrates a cross section of the wellbore with one of thepumps, for example pump 10B in FIG. 1 including a wet mateableelectrical/mechanical coupler 18B, an electrical cable 30 and severalfluid transport conduits 22A, 22B, 24A, 24B as explained with referenceto FIG. 1.

FIGS. 7A and 7B illustrate the difference in depth to which a pump maybe moved through production tubing 12 if the pump has a length and/ordiameter according to the present disclosure. In FIG. 7A a conventional,large diameter pump 110 is shown being inserted into the productiontubing 12 and being unable to pass a point 32 in the wellbore where thedog leg severity is sufficient to prevent further passage of the pump110. In FIG. 7B, by using a pump 10 with a smaller outer diameter and/orless length, the pump 10 may be able to pass the point 32 where dog legseverity stops a larger diameter and/or longer pump (as shown in FIG.7A).

FIG. 8 illustrates a cross section of a casing 14 where an ESP 10, a wetmateable electrical/mechanical connector 18, ESP cable 30 and flowconduits 22, 24 are shown. The example shown in FIG. 8 is based on anESP manufactured by Baker Hughes, Incorporated, Houston, Tex., undermodel designation PASS Slimline 3.38. Similar ESPs may be available fromother manufacturers. This type of ESP has a relatively small outerdiameter, but is still able to lift 2,500 barrels of wellbore fluid perday to the surface. If there is a requirement for 6-7,000 barrels ofwellbore fluid per day to be lifted to surface per day, then forexample, three of such ESPs may be installed in a production tubingsubstantially as explained with reference to FIGS. 1 and 3. Theinstallation may also include light intervention replaceable ESPs, whereeach ESP would include a wet mateable electrical/mechanical connector,for example, as explained with reference to FIGS. 1 and 3.

FIG. 9 illustrates how an ESP assembly 10A, equivalent to the uppermostpump shown in FIG. 1 may be removably placed within a segment (joint) ofthe production tubing 12. The ESP assembly 10A may be of types known inthe art and may comprise a sensor module 10A7 (having e.g., pressure,temperature and capacitance sensors), a motor section 10A6, a seal(protector) section 108A, a pump section (e.g., a centrifugal orprogressive cavity pump), a locking module section 10A3 to axially lockthe pump assembly 10A in the production tubing 12 and a fluid dischargesection 10A2. Some embodiments of the ESP assembly 10A may comprise afishing head 10A1 to enable retrieval of the ESP assembly 10A using awireline “fishing” head attached to the end of an armored electricalcable. The production tubing 12 may be configured, including the wetmateable electrical/mechanical connector 18, substantially as describedwith reference to FIG. 1 and FIG. 3. Fluid from the wellbore will bedelivered to the pump intake through the flow line(s) 22A mountedexternally on the production tubing 12. The pump section 10A5 willdeliver fluid upwardly to the surface through the discharge section 10A2of the ESP system 10A. Even though the locking module 10A3 isillustrated in FIG. 9 to be located below the discharge section 10A2,the locking module 10A3 may be disposed at any axial location along theESP assembly 10A. The wet mateable connector 18 routes electrical powerto the ESP system 10A. The discharge section 10A2 may also be on theside of the ESP assembly 10A, discharging fluids into one or severalfluid discharge lines (see FIG. 1) mounted externally on the productiontubing 12. The wet mateable connector 18 may comprise male connectorcontacts 18-1 on the ESP system 10A and female connector contacts 18-2on the connector portion disposed in the production tubing 12. A sealsection 10A-8 may stop fluid movement axially within the productiontubing 12 along the exterior of the ESP system 10A, so that all fluiddischarged by the ESP system 10A may be moved into the production tubing12 in a direction toward the surface.

FIG. 10 illustrates a system similar to the system shown in andexplained with reference to FIG. 1 with the inclusion of a gas separator34 in the production tubing 12 below the intake of the lowermost pump10C. The gas separator 34 device may be of a retrievable type landedwithin the production tubing 12, or it may be a permanent component aspart of the production tubing 12. Gas is discharged from the gasseparator 34 to one or more gas discharge tubes 36 mounted externally onthe production tubing 12, extending to a location axially above thepumps 10A, 10B, 10C. Having the gas separator 34 may increase theoperating efficiency of the pumps 10A, 10B, 10C by reducing cavitationor gas locking of the pumps 10A, 10B, 10C.

FIG. 11 illustrates a booster system 38 receiving gas at an inletthereof from one or several gas feeding conduit(s) 36, for example asexplained with reference to FIG. 10, and then discharging the gas intothe produced fluids from one or several wellbore pumps, e.g., 10A inFIG. 11. The booster system 38 may be powered by an electrical cable,e.g., 30, by hydraulic power fluid supplied from the surface through oneor several hydraulic control lines, or by the fluid discharged from oneor several wellbore pumps located below the booster 38. FIG. 11 omitspossible fluid discharge and intake flow lines from wellbore pumps thatcan be located in the wellbore below the illustrated pump 10A forclarity of the illustration. The booster 38 shown in FIG. 11 isapplicable to any system as described herein, specifically including,but without limitation, those shown in and explained with reference toFIG. 1, FIG. 3, FIG. 4 and FIG. 10. The booster's function is to draw ingas from below the pump(s) and then pressurize the gas enough for thegas to be discharged into the production tubing 12 above the pump(s).

FIG. 12 illustrates an example embodiment of a gas separator such asshown in FIG. 10 in more detail. The gas separator 34 may sealexternally against the interior of the casing 14. Fluids and gas 46 froma reservoir flows into the gas separator 36 through suitable openings116A in a lower packer 116 to an area between an inner tube 34A and anouter tube 34B of the gas separator 34. Thereafter the fluids and gas 46exit in the upper section into the area outside the gas separator 34,followed by traveling to intake ports in the lower side of the separator34. This results in gas 40 separating and rising to the upper section ofthe gas separator 34, and then entering through an upper packer 216 to,for example, one or several gas discharge tubes 36 extending to thesurface, or coupled to an area above the wellbore pump(s) as describedand explained with reference to FIGS. 10 and 11. It should be noted thatinstead of having fluids and gas in contact with the casing 14 outsidethe gas separator 34, the fluids and gas may also be contained within anouter concentric housing, or within one or several tubes mountedexternally.

Although only a few examples have been described in detail above, thoseskilled in the art will readily appreciate that many modifications arepossible in the examples. Accordingly, all such modifications areintended to be included within the scope of this disclosure as definedin the following claims.

What is claimed is:
 1. A pump system for a wellbore, comprising: aproduction tubing disposed in a wellbore; at least two pumps disposed inthe production tubing and axially spaced apart from each other, at leastone of the at least two pumps removable from the production tubing whilethe production tubing remains in place in the wellbore; and at least onefluid intake conduit disposed outside the production tubing and insidethe wellbore, the at least one fluid intake conduit in fluidcommunication with and providing a fluid transport path between aninterior of the production tubing below a lower one of the at least twopumps and at a position of an intake of an upper one of the at least twopumps; and at least one fluid discharge conduit disposed outside thetubing and inside the wellbore, the at least one fluid discharge conduitin fluid communication with and providing a fluid transport path betweenthe interior of the production tubing at a discharge of the lower one ofthe at least two pumps and either at an intake of or above the upper oneof the at least two pumps.
 2. The system of claim 1 wherein at least theupper one of the at least two pumps is seated in a wet mateableelectrical/mechanical connector disposed in the production tubing. 3.The system of claim 1 wherein both the upper one and the lower one ofthe at least two pumps is seated in a respective wet mateableelectrical/mechanical connector disposed in the production tubing. 4.The system of claim 1 further comprising a gas separator disposed in theproduction tubing below the lower one of the at least two pumps, the gasseparator having at least one gas discharge conduit disposed outside thetubing and inside the wellbore, the gas discharge conduits in fluidcommunication with the interior of the production tubing above the upperone of the at least two pumps.
 5. The system of claim 4 furthercomprising a booster disposed above the upper one of the at least twopumps having an intake in fluid communication with the at least one gasdischarge conduit, an outlet of the booster in fluid communication withan interior of the production tubing.
 6. The system of claim 3 whereinthe gas separator comprises an inner tube nested within an outer tubehaving fluid entry ports, the inner tube having fluid entry ports at anaxial position below the fluid entry ports in the outer tube, a sealdisposed between the inner tube and the outer tube disposed at alongitudinal position above the fluid entry ports in the outer tube, theseal having at least one gas discharge tube passing therethrough.
 7. Thesystem of claim 1 wherein at least the upper one of the at least twopumps is sealingly engaged to the interior of the production tubing soas to substantially prevent movement of fluid between an interior of theproduction tubing and an exterior of the at least the upper one of theat least two pumps.
 8. The system of claim 1 wherein the at least twopumps comprise electrically submersible pumps.
 9. The system of claim 1further comprising an annular seal element disposed between theproduction tubing and a casing disposed in the wellbore, the annularseal element disposed at a position below the lower one of the at leasttwo pumps.
 10. The system of claim 1 wherein the lower one of the atleast two pumps is coupled to the production tubing so as to requireremoval of the production tubing to remove the lower one of the at leasttwo pumps from the wellbore.
 11. The system of claim 1 furthercomprising a plurality of fluid flow conduits each being in fluidcommunication with an interior of the production tubing at longitudinalpositions corresponding to fluid communication positions of the at leastone fluid intake conduit.
 12. The system of claim 1 further comprising aplurality of fluid flow conduits each being in fluid communication withan interior of the production tubing at longitudinal positionscorresponding to fluid communication positions of the at least one fluiddischarge conduit.
 13. The system of claim 1 wherein each of the atleast two pumps has a fluid pumping rate enabling lift of a full flowrate of fluid from the wellbore to the surface, whereby failure of oneof the at least two pumps enables substitution of the other of the atleast two pumps to maintain full fluid flow from the wellbore to thesurface.
 14. The system of claim 1 wherein the at least two pumps havean outer diameter and/or a length such that the at least two pumps areable to move through a point of maximum dog leg severity in thewellbore.
 15. The system of claim 1 further comprising at least a thirdpump disposed in the production tubing intermediate the upper one of theat least two pumps and the lower one of the at least two pumps, the atleast a third pump having at least one respective fluid intake conduitdisposed outside the production tubing and inside the wellbore, the atleast one respective fluid intake conduit in communication with theinterior of the production tubing below the lower one of the at leasttwo pumps and at a position of an intake of the at least a third pump,the at least a third pump having at least one respective fluid dischargeconduit disposed outside the tubing and inside the wellbore, the atleast one fluid discharge conduit in fluid communication with theinterior of the production tubing proximate a discharge of the at leasta third pump and either proximate the intake of or above the upper oneof the at least two pumps.
 16. The system of claim 15 wherein the atleast a third pump is seated in a respective wet mateableelectrical/mechanical connector disposed in the production tubing. 17.The system of claim 16 wherein the at least a third pump is removablefrom the production tubing without removing the production tubing fromthe wellbore.
 18. The system of claim 15 wherein any combination of twoof the upper one of the at least two pumps and the at least a third pumphas a fluid pumping rate enabling lift of a full flow rate of fluid fromthe wellbore to the surface, whereby failure of any one of the at leasttwo pumps and the at least a third pump enables substitution of theother of the at least two pumps to maintain full fluid flow from thewellbore to the surface.
 19. A method for pumping fluid from a wellbore,comprising: operating at least one of at least two pumps disposed in aproduction tubing disposed in the wellbore, at least one of the at leasttwo pumps removable from the production tubing while the productiontubing remains in place in the wellbore, at least one fluid intakeconduit disposed outside the production tubing and inside the wellbore,the at least one fluid intake conduit in fluid communication with andproviding a fluid transport path between an interior of the productiontubing below a lower one of the at least two pumps and at a position ofan intake of an upper one of the at least two pumps, at least one fluiddischarge conduit disposed outside the tubing and inside the wellbore,the at least one fluid discharge conduit in fluid communication with andproviding a fluid transport path between the interior of the productiontubing at a discharge of the lower one of the at least two pumps andeither at an intake of or above the upper one of the at least two pumps.20. The method of claim 19 wherein each of the at least two pumps has afluid pumping rate enabling lift of a full flow rate of fluid from thewellbore to the surface, whereby failure of one of the at least twopumps enables substitution of the other of the at least two pumps tomaintain full fluid flow from the wellbore to the surface.
 21. Themethod of claim 19 further comprising operating at least a third pumpdisposed in the production tubing intermediate the upper one of the atleast two pumps and the lower one of the at least two pumps, the atleast a third pump having at least one respective fluid intake conduitdisposed outside the production tubing and inside the open wellbore, theat least one respective fluid intake conduit in communication with theinterior of the production tubing below the lower one of the at leasttwo pumps and at a position of an intake of the at least a third pump,the at least a third pump having at least one respective fluid dischargeconduit disposed outside the tubing and inside the wellbore, the atleast one fluid discharge conduit in fluid communication with theinterior of the production tubing proximate a discharge of the at leasta third pump and either proximate the intake of or above the upper oneof the at least two pumps.
 22. The method of claim 21 wherein anycombination of two of the upper one of the at least two pumps and the atleast a third pump has a fluid pumping rate enabling lift of a full flowrate of fluid from the wellbore to the surface, whereby failure of anyone of the at least two pumps and the at least a third pump enablessubstitution of the other of the at least two pumps to maintain fullfluid flow from the wellbore to the surface.